U.S. patent application number 13/266123 was filed with the patent office on 2012-02-16 for actuators and related methods.
Invention is credited to Napoleon Arizmendi, JR., Richard Paul Rubbo.
Application Number | 20120037360 13/266123 |
Document ID | / |
Family ID | 43011672 |
Filed Date | 2012-02-16 |
United States Patent
Application |
20120037360 |
Kind Code |
A1 |
Arizmendi, JR.; Napoleon ;
et al. |
February 16, 2012 |
ACTUATORS AND RELATED METHODS
Abstract
Various embodiments of the present invention disclose enhanced
and improved well production tools for increasing the stability of
production zones in a wellbore. Various embodiments of the present
invention generally relate to apparatuses, systems, and processes
for efficiently and effectively isolating zones within a
wellbore.
Inventors: |
Arizmendi, JR.; Napoleon;
(Magnolia, TX) ; Rubbo; Richard Paul; (The
Woodlands, TX) |
Family ID: |
43011672 |
Appl. No.: |
13/266123 |
Filed: |
April 26, 2010 |
PCT Filed: |
April 26, 2010 |
PCT NO: |
PCT/US10/01241 |
371 Date: |
October 24, 2011 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
61172676 |
Apr 24, 2009 |
|
|
|
Current U.S.
Class: |
166/250.01 ;
166/53 |
Current CPC
Class: |
E21B 23/04 20130101;
E21B 34/066 20130101; E21B 41/00 20130101; E21B 34/06 20130101;
E21B 33/14 20130101; E21B 43/26 20130101; E21B 2200/05 20200501;
E21B 2200/04 20200501; E21B 43/14 20130101; E21B 33/12 20130101;
E21B 43/11 20130101; E21B 2200/06 20200501 |
Class at
Publication: |
166/250.01 ;
166/53 |
International
Class: |
E21B 34/14 20060101
E21B034/14; E21B 47/00 20120101 E21B047/00; E21B 34/06 20060101
E21B034/06 |
Claims
1. An actuator module for actuating a downhole tool within a
wellbore comprising: a housing comprising a cylindrical chamber; a
piston disposed within the cylindrical chamber; a linkage member
operatively connecting the housing to the piston; an incompressible
fluid disposed within the cylindrical chamber on a first side of
the piston; a fluid path permitting a hydrostatic pressure of the
wellbore to be applied to a second side of the piston and at least
one surface of the linkage member, whereby the pressure of the
incompressible fluid increases in response to an increase in the
hydrostatic pressure of the wellbore; a gas chamber at least
partially filled with a compressible gas; an isolation module
comprising a pressure barrier between the cylindrical chamber and
the gas chamber; a controller comprising a microprocessor for
running a real time program that causes the controller to generate
an electrical output signal in response to at least one conditional
event; an electrical power source for powering the controller; and
an opening module for breaching the pressure barrier between the
cylindrical chamber and the gas chamber in response to the
electrical output signal generated by the controller, thereby
causing actuation of the downhole tool.
2. The actuator module as recited in claim 1, further comprising at
least one sensor interfaced with the controller for measuring at
least one environmental parameter, and wherein the at least one
conditional event is a function of at least one output from the at
least one sensor.
3. The actuator module as recited in claim 1, wherein the isolation
module further comprises a pressure retaining target section for
retaining a differential pressure generated between the cylindrical
chamber and the gas chamber.
4. The actuator as recited in claim 1, wherein the isolation module
further comprises a valve seat for providing engagement with the
opening module.
5. The actuator as recited in claim 4, wherein the opening module
comprises a valve and a valve seal for engaging the valve seat.
6. The actuator module as recited in claim 1, wherein the opening
module is an electrically activated disc cutter comprising a
cutting dart for perforating the pressure barrier.
7. The actuator module as recited in claim 1, wherein the
controller further comprises a communication receiver for receiving
communication signals from a remote location and wherein the at
least one conditional event is a function of at least the
communication signal.
8. The actuator module as recited in claim 1, wherein the
controller further comprises a communication transceiver for
transmitting communication signals to a remote location, wherein
the transmitted communication signal is an indication of the
occurrence of the at least one conditional event.
9. The actuator module of as recited in claim 1, wherein the
housing further comprises a shoulder for contacting the second side
of the piston to limit the axial displacement of the piston and the
linkage member.
10. A method for actuating a downhole tool within a wellbore
comprising: operatively connecting at least one member of the
downhole tool to the actuator module as recited in claim 1;
lowering the tool into the wellbore to a subterranean depth;
sensing the at least conditional event with the controller;
generating the electrical output signal with the controller in
response to at least one conditional event sensed by the
controller; and breaching the pressure barrier between the
cylindrical chamber and the gas chamber with the opening module in
response to the electrical output signal generated by the
controller; thereby causing actuation of the downhole tool.
11. The method as recited in claim 10, wherein operatively
connecting at least one member of the downhole tool to the actuator
module comprises operatively connecting the at least one member of
the downhole tool to a surface of the piston.
12. The method as recited in claim 11, wherein lowering the
downhole tool into the wellbore comprises lowering the downhole
tool into the wellbore to a subterranean depth, wherein at least
one surface of the piston that is not operatively connected to the
at least one member of the downhole tool is exposed to the
hydrostatic pressure of the wellbore.
13. The method as recited in claim 12, further comprising:
programming the microprocessor of the controller with a timing
countdown; starting the timing countdown; and generating the
controller electrical output signal with the controller in response
to the expiration of the timing countdown.
Description
RELATED APPLICATIONS
[0001] This application claims priority to U.S. Provisional Patent
Application 61/172,676 filed on Apr. 24, 2009, which is
specifically incorporated by reference in its entirety herein
without disclaimer. This application is further related to a
copending application titled NEW AND IMPROVED FRACTURE VALVE TOOLS
AND RELATED METHODS and a copending application titled NEW AND
IMPROVED BLAPPER VALVE TOOLS AND RELATED METHODS, both filed this
same day.
FIELD OF THE INVENTION
[0002] The present invention relates to, a method for treating oil
and gas wells. More specifically, various embodiments of the
present invention provide novel and non-obvious apparatuses,
systems, and processes for enhanced production of hydrocarbon
streams. More specifically, various embodiments of the present
invention generally relate to apparatuses, systems, and processes
for efficiently and effectively isolating zones within a
wellbore.
BACKGROUND OF THE INVENTION
[0003] Hydrocarbon fluids such as oil and natural gas are obtained
from a subterranean geologic formation, referred to as a reservoir;
by drilling a well that penetrates the hydrocarbon-bearing
formation. Once a wellbore has been drilled, the well must be
completed before hydrocarbons can be produced from the well. A
completion involves the design, selection, and installation of
equipment and materials in or around the wellbore for conveying,
pumping, or controlling the production or injection of fluids.
After the well has been completed, production of oil and gas can
begin.
[0004] The completion can include operations such as the
perforating of wellbore casing, acidizing and fracturing the
producing formation, and gravel packing the annulus area between
the production tubulars and the wellbore wall. For use in
multi-zone completions where it is required to perform fracture
stimulation treatments on separate zones.
[0005] Likewise, when a hydrocarbon-bearing, subterranean reservoir
formation does not have enough permeability or flow capacity for
the hydrocarbons to flow to the surface in economic quantities or
at optimum rates, hydraulic fracturing or chemical (usually acid)
stimulation is often used to increase the flow capacity. A wellbore
penetrating a subterranean formation typically consists of a metal
pipe (casing) cemented into the original drill hole. Holes
(perforations) are placed to penetrate through the casing and the
cement sheath surrounding the casing to allow hydrocarbon flow into
the wellbore and, if necessary, to allow treatment fluids to flow
from the wellbore into the formation.
[0006] Hydraulic fracturing consists of injecting fluids (usually
viscous shear thinning, non-Newtonian gels or emulsions) into a
formation at such high pressures and rates that the reservoir rock
fails and forms a plane, typically vertical, fracture (or fracture
network) much like the fracture that extends through a wooden log
as a wedge is driven into it. Granular proppant material, such as
sand, ceramic beads, or other materials, is generally injected with
the later portion of the fracturing fluid to hold the fracture(s)
open after the pressure is released. Increased flow capacity from
the reservoir results from the easier flow path left between grains
of the proppant material within the fracture(s). In chemical
stimulation treatments, flow capacity is improved by dissolving
materials in the formation or otherwise changing formation
properties.
[0007] When multiple hydrocarbon-bearing zones are stimulated by
hydraulic fracturing or chemical stimulation treatments, economic
and technical gains are realized by injecting multiple treatment
stages that can be diverted (or separated) by various means,
including mechanical devices such as bridge plugs, packers,
downhole valves, sliding sleeves, and baffle/plug combinations;
ball sealers; particulates such as sand, ceramic material,
proppant, salt, waxes, resins, or other compounds; or by
alternative fluid systems such as viscosified fluids, gelled
fluids, foams, or other chemically formulated fluids; or using
limited entry methods.
[0008] A typical approach is to drill and case with cement through
the various zones of interest. Then the operator will work from the
bottom of the well or from the lowest production zone:
[0009] 1. Perforate zone;
[0010] 2. Fracture or stimulate zone;
[0011] 3. Flow back and clean-up debris in the production test
zone.
[0012] 4. Plug the zone to keep it isolated.
[0013] There are numerous plugs that can be used, including, but
not limited to, a cast iron bridge plug (which is drillable); a
retrievable bridge plug (which is retrievable); a composite bridge
plug (which is drillable); a cement plug; and/or the like.
[0014] In general, the process is repeated going back uphole at
each production zone where production is desired. There can be as
few as one zone and an infinite maximum number of zones. Typically,
at the uphole most zone, the step of plugging the zone is
skipped.
[0015] To begin production from all of the plugged zones, a drill
string is lowered with a mill or cutter to mill or drill through
all the various plugs at the different zones, wherein all milled
zones are allowed to be in communication with the wellbore.
[0016] The completion is then set in the wellbore and the well put
on production. In various embodiments, a completion is as simple as
production tubing terminated into a packer above the top zone. Or,
it could consist of a series of packing placed between each set of
parts connected by tubing with valves in between. The valves or
controllers are capable of being wireline operable, sometimes
called sliding sleeves or sliding side doors, or they could be
remotely operated valves that depend on a series of hydraulic or
electric, or both control lines, typically called interval control
valves (ICVs).
[0017] Regardless of completion type, what is found is that: the
overall production rate and remainder obtained after production are
universally less than what it was predicted to be taking into
account of the reservoir properties demonstrated in each individual
zone during the flowbacks testing following fracture of the
wellbore.
[0018] Some of the reduced performance can be attributed to cross
flow between zones and other interference phenomena. However, the
reduced performance is typically of such magnitude that all of the
reduction cannot be attributable to cross flow.
[0019] In various situations, a more significant cause of
production impairment is damage to the formation that takes place
during the milling of the plugs. While the use of composite versus
cast iron bridge plugs has significantly reduced the time and
expense required for milling, the process invariably requires
circulation of fluids and managing the well bore pressures in a way
that results in contamination of various production zones of the
reservoir with well bore fluids, such that the effective
permeability of the zones is reduced. This is often thought of as
slate damage. In essence, the process of removing the plugs can
reverse much of the productivity improvements provided by the
initial fracture stimulation.
[0020] Multiple valve assemblies may be used in coordination with
multiple zones of production. In one embodiment, an individual zone
of production can be completed and isolated before working on
another zone. Criteria utilized for determining the sequence of
production may include formation pressures, production rates, and
recovery from each zone as disclosed in U.S. Pat. No.
6,808,020.
[0021] Once a zone has been completed, completion fluids within the
wellbore can leak off into the formation in a process commonly
known as "fluid loss". The wellbore may fill with formation fluids
as a result of the reduction of hydrostatic pressure on the
completed zone. A blow-out may occur if fluid loss occurs during
completion activities. Fluid may be added to the wellbore to
maintain hydrostatic pressure, as disclosed in U.S. Pat. No.
6,808,020.
[0022] The purpose of cementing the casing is to provide a seal
between zones since the drilling of the hole breaks through the
natural barriers. Perforations (from sharper changes) provide
communication through casing and cement to formation. In High Perm
reservoirs, perforation alone is enough to put the well on
production.
[0023] In Low Perm reservoirs (tight reservoirs), one creates
additional exposure by creating fractures in the rock. That can
extend far from the well bore. Typically, the fracture (or frac)
fluid contains proppant solids designed to hold the fractures open
(propped open) so that production fluids flow easily through the
fracture back into the well bore.
[0024] In instances where fracturing is not necessary, perforation
quality is critical because the perforation needs to cut through
the casing, the cement, and extend into the formation enough to
pass any formation damage that occurs during drilling the well.
[0025] Commonly, in various embodiments, all that is needed to
fracture stimulate is the perforation job to provide communication
from the wellbore to the reservoir. Once the fracture is initiated,
the Frac job will typically cause the area around the plugged hole
in the casing to be removed. In various further embodiments,
perforation through only the casing is sufficient to allow the
fracture pressures to cause the cement to fail in the area about
the casing perforation hole and thereby allow communication.
However, in various embodiments, the fracture pressure will not be
sufficient to break the cement.
[0026] Systems and processes for removing fluids from a wellbore
are known in the art. Various examples of prior art systems and
processes include U.S. Pat. No. 7,426,938; U.S. Pat. No. 7,114,558;
U.S. Pat. No. 7,059,407; U.S. Pat. No. 6,957,701; U.S. Pat. No.
6,808,020; U.S. Pat. No. 6,732,803; U.S. Pat. No. 6,631,772; U.S.
Pat. No. 6,575,247; U.S. Pat. No. 6,520,255; U.S. Pat. No.
6,065,536; U.S. Pat. No. 5,673,658; U.S. Pat. No. 4,852,391; U.S.
Pat. No. 4,559,786; U.S. Pat. No. 4,557,325 U.S. Pat. No.
2,067,408; U.S. Pat. No. 2,925,775; U.S. Pat. No. 2,968,243; U.S.
Pat. No. 2,986,214; U.S. Pat. No. 3,028,914; U.S. Pat. No.
3,111,988; U.S. Pat. No. 3,118,501; U.S. Pat. No. 3,366,188; U.S.
Pat. No. 3,427,652; U.S. Pat. No. 3,429,384; U.S. Pat. No.
3,547,198; U.S. Pat. No. 3,662,833; U.S. Pat. No. 3,712,379; U.S.
Pat. No. 3,739,723; U.S. Pat. No. 3,874,461; U.S. Pat. No.
4,102,401; U.S. Pat. No. 4,113,314; U.S. Pat. No. 4,137,182; U.S.
Pat. No. 4,139,060; U.S. Pat. No. 4,244,425; U.S. Pat. No.
4,415,035; U.S. Pat. No. 4,637,468; U.S. Pat. No. 4,671,352; U.S.
Pat. No. 4,702,316; U.S. Pat. No. 4,776,393; U.S. Pat. No.
4,809,781; U.S. Pat. No. 4,860,831; U.S. Pat. No. 4,865,131; U.S.
Pat. No. 4,867,241; U.S. Pat. No. 5,025,861; U.S. Pat. No.
5,103,912; U.S. Pat. No. 5,131,472; U.S. Pat. No. 5,161,618; U.S.
Pat. No. 5,309,995; U.S. Pat. No. 5,314,019; U.S. Pat. No.
5,353,875; U.S. Pat. No. 5,390,741; U.S. Pat. No. 5,485,882; U.S.
Pat. No. 5,513,703; U.S. Pat. No. 5,579,844; U.S. Pat. No.
5,598,891; U.S. Pat. No. 5,669,448; U.S. Pat. No. 5,704,426; U.S.
Pat. No. 5,755,286; U.S. Pat. No. 5,803,178; U.S. Pat. No.
5,812,068; U.S. Pat. No. 5,832,998; U.S. Pat. No. 5,845,712; U.S.
Pat. No. 5,865,252; U.S. Pat. No. 5,890,536; U.S. Pat. No.
5,921,318; U.S. Pat. No. 5,934,377; U.S. Pat. No. 5,947,200; U.S.
Pat. No. 5,954,133; U.S. Pat. No. 5,990,051; U.S. Pat. No.
5,996,687; U.S. Pat. No. 6,003,607; U.S. Pat. No. 6,012,525; U.S.
Pat. No. 6,053,248; U.S. Pat. No. 6,098,713; U.S. Pat. No.
6,116,343; U.S. Pat. No. 6,131,662; U.S. Pat. No. 6,186,227; U.S.
Pat. No. 6,186,230; U.S. Pat. No. 6,186,236; U.S. Pat. No.
6,189,621; U.S. Pat. No. 6,241,013; U.S. Pat. No. 6,257,332; U.S.
Pat. No. 6,257,338; U.S. Pat. No. 6,272,434; U.S. Pat. No.
6,286,598; U.S. Pat. No. 6,296,066; U.S. Pat. No. 6,394,184; U.S.
Pat. No. 6,408,942; U.S. Pat. No. 6,446,727; U.S. Pat. No.
6,474,419; U.S. Pat. No. 6,488,082; U.S. Pat. No. 6,494,260; U.S.
Pat. No. 6,497,284; U.S. Pat. No. 6,497,290; U.S. Pat. No.
6,543,538; U.S. Pat. No. 6,543,540; U.S. Pat. No. 6,547,011, the
contents all of which are hereby incorporated by reference as if
reproduced in its entirety.
SUMMARY OF THE INVENTION
[0027] In general, various embodiments of the present invention
relate to apparatuses, systems and processes for isolating at least
one production zone in a wellbore.
[0028] The present invention provides a method, system, and
apparatus for perforating and stimulating multiple formation
intervals, which allows each single zone to be treated with an
individual treatment stage while eliminating or minimizing the
problems that are associated with existing coiled tubing or jointed
tubing stimulation methods and hence providing significant economic
and technical benefit over existing methods.
[0029] Various embodiments of the present invention comprise a
fracture valve tool comprising a mandrel defining a through
passage, wherein said mandrel comprises at least a first mandrel
port extending from an exterior surface of said mandrel to an
interior surface of said mandrel; and wherein there is a rotating
sleeve rotatably positioned on said mandrel, said rotating sleeve
comprising at least one sleeve port, wherein said rotating sleeve
rotates between at least a first position wherein said at least one
sleeve port does not align with said at least one mandrel port and
a second position wherein said at least one sleeve port is at least
partially aligned with said at least one mandrel port whereby
communication from said exterior surface of said mandrel to said
interior surface of said mandrel is possible. In a further
embodiment, the fracture valve tool further comprises cement flow
paths at various locations around the circumference of the fracture
valve tool.
[0030] An embodiment of the present invention is a fracture valve
tool for running with a production string comprising at least one
production tubing, said fracture valve tool comprising a mandrel
defining a through passage smaller than that of said production
tubing; a blapper valve; and a valve actuator, wherein said valve
actuator is can be actuated into at least a first position wherein
said rotary valve is open and said through passage is open and at
least a second position wherein said blapper valve is closed and
said through passage is closed. In a further embodiment, the
fracture valve tool further comprises cement flow paths at various
locations around the circumference of the fracture valve tool. In
yet another embodiment, the fracture valve tool further comprises
at least one packer assembly comprising at least one packer and a
mandrel. In an embodiment of the present invention, the at least
one packer assembly is positioned above said blapper valve. In
another embodiment, the at least one packer assembly is positioned
about a hydrocarbon producing zone. In an embodiment of the present
invention, the wellbore exterior to the fracture valve tool is not
cemented. In another embodiment, the fracture valve tool further
comprises a battery pack operably connected to said valve actuator.
In another embodiment, the fracture valve tool further comprises a
piston operably connected to said valve actuator for rotating said
blapper valve between said open position and said closed position.
In yet another embodiment, the fracture valve tool further
comprises a control wire running downhole to the actuator for
controlling the actuator.
[0031] An embodiment of the present invention is a completed
wellbore with at least a first production zone, said completed
wellbore further comprising a casing string and at least one
fracture valve tool connected to a production string and positioned
below said first production zone. In another embodiment, the
completed wellbore further comprises a second production zone and a
second fracture valve tool connected to a production string and
positioned below said second production zone. Another embodiment of
the present invention is a process for producing a hydrocarbon from
the completed wellbore comprising the steps of: opening said
fracture valve tool; fracturing said production zone; flowing a
drilling mud; and producing hydrocarbon up the production
string.
[0032] Another embodiment of the present invention is a production
string comprising a fracture valve tool for running with a
production string comprising at least one production tubing, said
fracture valve tool comprising a mandrel defining a through passage
smaller than that of said production tubing; a rotary valve; and a
valve actuator; wherein said mandrel comprises at least a first
mandrel port extending from an exterior surface of said mandrel to
an interior surface of said mandrel; and wherein there is a
rotating sleeve rotatably positioned on said mandrel, said rotating
sleeve comprising at least one sleeve port, wherein said rotating
ported sleeve rotates between at least a first position wherein
said at least one sleeve port does not align with the at least one
mandrel port and a second position wherein said at least one sleeve
port is at least partially aligned with said at least one mandrel
port whereby communication from said exterior surface of said
mandrel to said interior surface of said mandrel is possible.
[0033] Yet another embodiment of the present invention is a casing
string comprising a fracture valve tool comprising a mandrel
comprising at least a first open end and a second open end; wherein
said mandrel comprises at least a first mandrel port extending from
an exterior surface of said mandrel to an interior surface of said
mandrel; and wherein there is a rotating sleeve rotatably
positioned on said mandrel, said rotating sleeve comprising at
least one sleeve port, wherein said rotating sleeve rotates between
at least a first position wherein said at least one sleeve port
does not align with said at least one mandrel port and a second
position wherein said at least one sleeve port is at least
partially aligned with said at least one mandrel port whereby
communication from said exterior surface of said mandrel to said
interior surface of said mandrel is possible. In a further
embodiment, the mandrel is connected to one of a casing string or a
production string. In another embodiment, the fracture valve tool
is in a wellbore. In yet another embodiment, the fracture valve
tool is in a closed position. In yet another embodiment, the
fracture valve tool is in an open position. In an embodiment of the
present invention, the fracture valve tool is above or below an oil
and gas formation. In another embodiment of the present invention,
the fracture valve tool is both above and below an oil and gas
formation. In an embodiment of the present invention, the casing
string further comprises at least one packer. An embodiment of the
present invention is a completed wellbore comprising the casing
string.
[0034] An embodiment of the present invention is a method of
isolating production zones comprising connecting at least one
fracture valve tool to the production string; and positioning the
at least one fracture valve tool below a first production zone,
wherein the at least one fracture valve tool is in a closed
position. In another embodiment, the method comprises connecting a
second fracture valve tool to the production string and positioned
below a second production zone, wherein the second fracture valve
tool is in a closed position.
[0035] Another embodiment of the present invention is a method of
completing a wellbore comprising assembling a production string
comprising a fracture valve tool for running with a production
string comprising at least one production tubing, said fracture
valve tool comprising a mandrel, wherein said mandrel defines a
through passage smaller than that of said production tubing and
comprises at least a first mandrel port extending from an exterior
surface of said mandrel to an interior surface of said mandrel;
rotating a rotating sleeve positioned on said mandrel, said
rotating sleeve comprising at least one sleeve port; wherein said
rotating sleeve rotates so that at least one sleeve port is at
least partially aligned with said at least one mandrel port whereby
communication from said exterior surface of said mandrel to said
interior surface of said mandrel is possible; fracturing production
zone; flowing a drilling mud; and producing hydrocarbon up the
production string.
[0036] Certain embodiments of the invention describe a mandrel
defining a through passage smaller than that an exterior portion of
the mandrel comprising a rotary valve operatively connected to the
through passage and a valve actuator, wherein said valve actuator
is can be actuated into at least a first position wherein said
rotary valve is open and said through passage is open and at least
a second position wherein said rotary valve is closed and said
through passage is closed.
[0037] In more specific embodiments, the actuator may comprise a
battery pack operably connected to the valve actuator. In other
embodiments, the rotary valve comprises a piston, wires or a shaft
operably connected to a valve actuator for rotating the rotary
valve between open and closed positions.
[0038] Still further, the invention contemplates that the actuator
may have a control wire running downhole to the actuator for
controlling the actuator.
[0039] Various further embodiments comprise a measurement line
extending from the mandrel for taking data measurements downhole at
about the production zone. Examples of measurements that might be
taken include but are not limited to density, temperature,
pressure, pH, and/or the like. Such measurements can be used to
help run the well. In various embodiments, a cable would
communicate the data to an operator at the surface. In various
further embodiments, the data is transmitted remotely to an
operator. In further embodiments, the data is stored.
[0040] Such a valve arrangement as herein disclosed would relieve
stress to the formation, as no stressful perforation would be
required in various embodiments. As well, cementing of the well
would be impeded by cavities or rough portions on typical
completions. In various embodiments, the mandrel interior surface
is fairly smooth and would allow the passage of a cement wiper
plug.
[0041] Various methods of actuating the valve actuator are
possible. In an embodiment a battery pack is operably connected to
the valve actuator. The battery pack can be used to supply power to
all manner of actuation devices and motors, such as a pneumatic
motor, a reciprocating motor, a piston motor, and/or the like. In
various further embodiments, the actuator is controlled by a
control line from the surface. The control line can supply power to
the actuator, supply a hydraulic fluid, supply light, fiber optics,
and/or the like. In an embodiment, there are three control lines
running to the actuator, such that one opens the actuator, one
closes the actuator, and one breaks any cement that is capable of
fouling the actuator and preventing it from opening. The cement on
the actuator may be broken by any method common in the art such as
vibration, an explosive charge, a hydraulic force, a movement up or
down of the valve, and/or the like. Generally, any necessary
structures for performing the vibrations, charges, movements,
and/or the like can be housed in the mandrel about the valve.
[0042] In various embodiments, a piston is operably connected to
the valve actuator for rotating the rotary valve between the open
position and the closed position.
[0043] Various embodiments of the present invention comprise a
completed wellbore with at least a first production zone, the
completed wellbore further comprising a cemented casing string, a
production string, and at least one fracture valve tool as herein
disclosed connected to the production string and positioned below
the first production zone, wherein the at least one fracture valve
tool is cemented in a closed position. Further embodiments comprise
a second production zone and a second fracture valve tool as herein
disclosed connected to the production string and positioned below
the second production zone, wherein the second fracture valve tool
is cemented in a closed position.
[0044] Further embodiments disclose a process for producing a
hydrocarbon from a completed wellbore, the process comprising the
steps of: opening a rotary valve; fracturing a production zone;
flowing a drilling mud through the completed wellbore for clean up;
and, closing the rotary valve, wherein a hydrocarbon is produced up
the production string.
[0045] In further embodiments, the invention discloses repeating
the steps of: opening a second rotary valve; fracturing a second
production zone; flowing a drilling mud through the completed
wellbore for clean up; and closing the second rotary valve, wherein
a hydrocarbon is produced up the production string.
[0046] Various further embodiments of the present invention
disclose a casing string section for a hydrocarbon production well,
the casing section comprising: a mandrel comprising at least a
first mandrel port extending from an exterior surface of the
mandrel to an interior surface of the mandrel; and, a rotating
sleeve rotatably positioned on the mandrel, the rotating sleeve
comprising at least one sleeve port, wherein the rotating ported
sleeve rotates between at least a first position wherein the at
least one sleeve port covers the at least one mandrel port and a
second position wherein the at least one sleeve port is at least
partially aligned with the at least one mandrel port whereby
communication from the exterior surface of the mandrel to the
interior surface of the mandrel is possible. In various embodiments
there is a control line associated with the mandrel.
[0047] Further embodiments disclose a cement flowpath passing
through the mandrel. In an embodiment, the rotatable sleeve is a
ball valve or is on a ball valve.
[0048] In various embodiments, this system can be run without a
production string and still selectively isolate the production
zones in the wellbore. In various embodiments, as a casing string
is run, the sliding sleeves are aligned about the production zones.
The sliding sleeves are maintained in a closed position. When the
last piece of casing is run and the casing string set, by packer or
not, cement can be added as normal into the casing string. At each
casing string section, a packer or other device will divert the
cement into the cement flowpath for filling. The annulus of the
wellbore can likewise be filled as normal.
[0049] Various embodiments comprise a completed wellbore for
producing at least one hydrocarbon without the need for perforation
comprising a casing string comprising at least one casing string
section as herein disclosed positioned about a hydrocarbon
production zone, wherein a cement is flowed into a cement flowpath
in the casing string section and back up the exterior of the casing
string section in the wellbore. In various embodiments, there is at
least one casing string section as herein disclosed per hydrocarbon
production zone.
[0050] When production is desired, one or more of the rotary valves
can be actuated such that communication is capable from the
exterior of the mandrel to the interior of the mandrel. Typically,
a fracture is required to allow production and clear any cement
that has migrated into the zone. After the fracture, the zone is
cleaned by flowing a drilling mud and production can begin. If
production needs to be stopped, the rotary valve can be actuated
again and the valve closed.
[0051] In various embodiments of the present invention, the
fracture valve tool may be used with various types of valves
including rotary valves, blapper valves, J valves, fill-up valves,
circulating valves, sampler valves, pilot valves, solenoid valves,
safety valves, and/or the like.
[0052] Embodiments of the present invention also include an
actuator module and the use of such an actuator module for
actuating a downhole tool within a wellbore. In certain
embodiments, the actuator may include a housing comprising a
chamber and piston disposed within the chamber, i.e. a piston
chamber or a cylindrical chamber with a linkage member operatively
connecting the housing to the piston.
[0053] Still further, the actuator module may comprise an
incompressible fluid disposed within the chamber. For instance, in
certain embodiments, an incompressible fluid may be disposed within
the chamber on one side or a first side of the piston and a fluid
path permitting hydrostatic pressure of the wellbore may be applied
to the second side of the piston. In addition to the fluid path
permitting hydrostatic pressure of the wellbore being applied to
the second side of the piston, the fluid path may be also be
applied to at least one surface of the linkage member of the
actuator module whereby the pressure of the incompressible fluid
increases in response to an increase in the hydrostatic pressure of
the wellbore.
[0054] In further embodiments, the housing of the actuator module
may include or comprise a shoulder for contacting the second side
of the piston to limit axial displacement of the piston and the
linkage member.
[0055] Additionally, the actuator module may comprise a gas chamber
at least partially filled with a compressible gas, an isolation
module comprising a pressure barrier between the piston chamber and
the gas chamber.
[0056] Still further, the actuator module of the present invention
may include a controller comprising a microprocessor for running a
real time program that causes the controller to generate an
electrical output signal in response to at least one conditional
event and an electrical power source for powering the
controller.
[0057] Additionally, the actuator module may comprise an opening
module for breaching the pressure barrier between the piston
chamber and the gas chamber in response to the electrical output
signal generated by the controller in order to cause actuation of
the downhole tool.
[0058] In further embodiments, the actuator module may comprise at
least one sensor interface with the controller for measuring a
parameter, such as an environmental parameter, wherein the
controller generates an electrical output signal in response to at
least one conditional event and wherein the conditional event is a
function of at least one output from the sensor or sensors.
[0059] In additional embodiments wherein an actuator module is
contemplated, the isolation module of the actuator module may
comprise a pressure retaining target section for retaining
differential pressure generated between the piston or cylindrical
chamber and the gas chamber. Still further, the isolation module
may comprise a valve seat for providing engagement with the opening
module which is designed to breach the pressure barrier between the
cylindrical or piston chamber and the gas chamber.
[0060] In certain embodiments, the opening module further comprises
a valve and a valve seal for engaging the valve seat of the
isolation module. In other embodiments, the opening module is an
electrically activated disc cutter comprising a cutting dart for
perforating the pressure barrier.
[0061] The actuator module may further comprise a controller
comprising a microprocessor for running a real time program that
causes the controller to generate an electrical output signal in
response to at least one conditional event which may include a
communication receiver for receiving communication signals from a
remote location. It is further contemplated that the conditional
event is a function of the communication signal. The controller
comprising a microprocessor for running a real time program that
causes the controller to generate an electrical output signal in
response to at least one conditional event may further include a
communication transceiver for transmitting communication signals to
a remote location wherein the transmitted communication signal is
an indication of the occurrence of the conditional event.
[0062] Other embodiments of the inventions described herein pertain
to methods of using an actuator module. In certain embodiments, a
method for actuating a downhole tool within a wellbore includes
operatively connecting one member (at least one or more) of the
downhole tool to the actuator module, lowering the tool into the
wellbore to a subterranean depth, sensing a conditional event or
events with the controller, generating an electrical output signal
with the controller in response to the conditional event or events
sensed by the controller and breaching the pressure barrier between
the cylindrical chamber and the gas chamber with the opening module
in response to the electrical output signal generated by the
controller, thereby causing actuation of the downhole tool.
[0063] In still further embodiments of methods pertaining to the
use of an actuator module, the actuator module may operatively
connect a member of the downhole tool to a surface of the
piston.
[0064] Other embodiments of the methods pertaining to the use of an
actuator module contemplate lowering the downhole tool into the
wellbore to a subterranean depth wherein one surface of the piston
that is not operatively connected to a member of the downhole tool
is instead exposed to the hydrostatic pressure of the wellbore.
[0065] Additional embodiments of the methods pertaining to the use
of an actuator module related to the controller. For instance, in
certain embodiments, the methods relate to programming the
controller's microprocessor with a timing countdown, starting the
timing countdown and generating the controller electrical output
signal with the controller in response to the expiration of the
timing countdown.
[0066] The foregoing has outlined rather broadly the features of
the present disclosure in order that the detailed description that
follows may be better understood. Additional features and
advantages of the disclosure will be described hereinafter, which
form the subject of the claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0067] In order that the manner in which the above-recited and
other enhancements and objects of the invention are obtained, a
more particular description of the invention briefly described
above will be rendered by reference to specific embodiments thereof
which are illustrated in the appended drawings. Understanding that
these drawings depict only typical embodiments of the invention and
are therefore not to be considered limiting of its scope, the
invention will be described with additional specificity and detail
through the use of the accompanying drawings in which:
[0068] FIG. 1 is an illustration of a cross section of an
embodiment of the present invention with an embodiment of a mandrel
with a rotary valve.
[0069] FIG. 2 is an illustration of the cross section of FIG. 1 in
a different orientation.
[0070] FIG. 3 is an illustration of an alternate embodiment of the
present invention with an embodiment of a fracture valve tool.
[0071] FIG. 4 is an illustration of a cross section A-A of FIG.
3.
[0072] FIG. 4 is an illustration of a cross section B-B of FIG.
3.
[0073] FIG. 5 is an illustration of an alternate embodiment of the
present invention with an embodiment of a casing string
section.
[0074] FIG. 6 is an illustration of an alternate embodiment of the
present invention with an embodiment of an actuation device.
[0075] FIG. 7 is an illustration of two wellbore completions.
[0076] FIGS. 8A and 8B are illustrations of the actuator device in
its pre activated state.
[0077] FIGS. 9A and 9B are illustrations of the actuator device in
its activated state.
[0078] FIG. 10A is an illustration of an isolation module with an
integral thin target section.
[0079] FIGS. 10B and 10C are illustrations of the isolation module
with a disk welded to a face of a support member.
[0080] FIG. 11A is an illustration of a pyrotechnic driven opening
module prior to actuation.
[0081] FIG. 11B is an illustration of a pyrotechnic driven opening
module after actuation.
[0082] FIG. 12A is an illustration of a spring driven bimetallic
fuse wire activated opening module installed into an isolation
module before device actuation.
[0083] FIG. 12B is an illustration of a spring driven bimetallic
fuse wire activated opening module installed into an isolation
module after device actuation.
[0084] FIG. 13A is an illustration of a spring driven solenoid
activated opening module installed into an isolation module prior
to device actuation.
[0085] FIG. 13B is an illustration of a spring driven solenoid
activated opening module installed into an isolation module after
device actuation.
[0086] FIG. 14 is an illustration if an interface to electrically
conductive instrument wire or (I-wire) cable assembly.
[0087] FIG. 15A is an illustration of a solenoid valve based
opening module in the pre-actuated state.
[0088] FIG. 15B is an illustration of a solenoid valve based
opening module in the after actuation.
LIST OF REFERENCE NUMERALS
[0089] mandrel with rotary valve 1 [0090] mandrel 2 [0091] rotary
valve 3 [0092] valve tip 4 [0093] valve actuator 5 [0094] piston 7
[0095] fracture valve tool 100 [0096] cement flowpaths 105 and 109
[0097] longitudinally extending borehole 107 [0098] fracture valve
tool mandrel 110 [0099] sleeve port 120 and 123 [0100] rotating
sleeve 125 [0101] mandrel port 127 [0102] casing 130 [0103] spacer
131 [0104] cement flowpaths 132 [0105] exterior surface of the
mandrel 140 [0106] control line 145 [0107] interior surface of the
mandrel 150 [0108] casing string section 200 [0109] casing string
section valve actuator 210 [0110] casing string section (with a
rotatable sleeve in a longer casing section) 300 [0111] port 310
[0112] connection of another casing section 320 [0113] well
completion 400 [0114] multiple fracture valve tools 410 [0115]
packers 415 [0116] bottom sub or packer 417 [0117] ports 419 [0118]
multiple production zones 420 [0119] cemented section 430 [0120]
well completion 500 [0121] casing string section 510 [0122] rotary
sleeve 515 [0123] packed section 517 [0124] production zones 520
[0125] cemented section 530 [0126] bulkhead 622 [0127] shoulder 623
[0128] o-ring 700 [0129] second o-ring 701 [0130] wire set 800
[0131] second wire set 801 [0132] linear grove 810 [0133] integral
thin target section 820 [0134] isolation module with a disk welded
830 [0135] diverging radii 840 [0136] hole 850 [0137] spring 900
[0138] opening module 901 [0139] bimetallic fuse wire 902 [0140]
solid ring 903 [0141] solenoid sleeve 904 [0142] heating element
910 [0143] insulated potting material 911. [0144] stainless steel
metal tube 1000 [0145] insulation layer 1001 [0146] conductor cable
1002 [0147] jam nut 1003 [0148] metal ferrule seals 1004 [0149]
cable assembly wire 1005 [0150] I-wire cable assembly 1006 [0151]
wellbore fluid 1007 [0152] interior of the tool 1008 [0153]
bulkhead insulator 1009 [0154] tool end cap 1010 [0155] I-Wire
cable assembly PCBA 1011 [0156] I-Wire cable assembly device body
1012 [0157] valve seat 1100 [0158] extended valve stem 1101 [0159]
solenoid valve based opening module 1102 [0160] isolation module
1106 [0161] fluid communication path 1107
DETAILED DESCRIPTION OF THE ILLUSTRATIVE EMBODIMENTS
[0162] In the following description, certain details are set forth
such as specific quantities, sizes, etc. so as to provide a
thorough understanding of the present embodiments disclosed herein.
However, it will be obvious to those skilled in the art that the
present disclosure may be practiced without such specific details.
In many cases, details concerning such considerations and the like
have been omitted inasmuch as such details are not necessary to
obtain a complete understanding of the present disclosure and are
within the skills of persons of ordinary skill in the relevant
art.
[0163] The present invention will be described in connection with
its preferred embodiments. However, to the extent that the
following description is specific to a particular embodiment or a
particular use of the invention, this is intended to be
illustrative only, and is not to be construed as limiting the scope
of the invention. On the contrary, the description is intended to
cover all alternatives, modifications, and equivalents that are
included within the spirit and scope of the invention, as defined
by the appended claims.
A. Terminology
[0164] For purposes of description herein, the terms "upper,"
"lower," "right," "left," "rear," "front," "vertical,"
"horizontal," and derivatives thereof shall relate to the invention
as oriented in FIG. 1. However, it is to be understood that the
invention may assume various alternative orientations, except where
expressly specified to the contrary. It is also to be understood
that the specific devices and processes illustrated in the attached
drawings, and described in the following specification are simply
exemplary embodiments of the inventive concepts defined in the
appended claims. Hence, specific dimensions and other physical
characteristics relating to the embodiments disclosed herein are
not to be considered as limiting, unless the claims expressly state
otherwise.
[0165] The following definitions and explanations are meant and
intended to be controlling in any future construction unless
clearly and unambiguously modified in the following Description or
when application of the meaning renders any construction
meaningless or essentially meaningless. In cases where the
construction of the term would render it meaningless or essentially
meaningless, the definition should be taken from Webster's
Dictionary, 3rd Edition. Definitions and/or interpretations should
not be incorporated from other patent applications, patents, or
publications, related or not, unless specifically stated in this
specification or if the incorporation is necessary for maintaining
validity.
[0166] As used herein, the term "downhole" means and refers to a
location within a borehole and/or a wellbore. The borehole and/or
wellbore can be vertical, horizontal or any angle in between.
[0167] As used herein, the term "fracturing," "frac" or "Frac" is a
well stimulation process performed to improve production from
geological formations where natural flow is restricted. Typically,
fluid is pumped into a well at sufficiently high pressure to
fracture the formation. A proppant (sand or ceramic material) is
then added to the fluid and injected into the fracture to prop it
open, thereby permitting the hydrocarbons to flow more freely into
the wellbore. Once the sand has been placed into the fracture, the
fluid flows out of the well leaving the sand in place. This creates
a very conductive pipeline into the formation. Normal fracturing
operations require that the fluid be viscosified to help create the
fracture in the reservoir and to carry the proppant into this
fracture. After placing the proppant, the viscous fluid is then
required to "break" back to its native state with very little
viscosity so it can flow back out of the well, leaving the proppant
in place.
[0168] As used herein, the term "borehole" means and refers to a
hole drilled into a formation.
[0169] As used herein, the term "annulus" refers to any void space
in an oil well between any piping, tubing or casing and the piping,
tubing or casing immediately surrounding it. The presence of an
annulus gives the ability to circulate fluid in the well, provided
that excess drill cuttings have not accumulated in the annulus
preventing fluid movement and possibly sticking the pipe in the
borehole.
[0170] As used herein, the term "valve" means and refers to any
valve, including, but not limited to flow regulating valves,
temperature regulating valves, automatic process control valves,
anti vacuum valves, blow down valves, bulkhead valves, free ball
valves, fusible link or fire valves, hydraulic valves, jet
dispersal valve, penstock, plate valves, radiator valves, rotary
slide valve, rotary valve, solenoid valve, spectacle eye valve,
thermostatic mixing valve, throttle valve, globe valve,
combinations of the aforesaid, and/or the like.
[0171] As used herein, "perforate" means and refers to providing
communication from the wellbore to the reservoir. Perforations (or
holes) may be placed to penetrate through the casing and the cement
sheath surrounding the casing to allow hydrocarbon flow into the
wellbore and, if necessary, to allow treatment fluids to flow from
the wellbore into the formation.
[0172] As used herein, "mandrel" means and refers to a cylindrical
bar, spindle, or shaft around which other parts are arranged or
attached or that fits inside a cylinder or tube.
[0173] As used herein, "packer", means and refers to a piece of
equipment that comprises of a sealing device, a holding or setting
device, and an inside passage for fluids. In one embodiment it is a
plug that is used to isolate sections of a well or borehole.
B. Fracture Valve and Fracture Valve Tool
[0174] Embodiments of the present invention may be used in any
wellbore, including multi-zone completions where it is required to
perform fracture stimulation on separate zones of the formation,
and/or the like.
[0175] The present invention provides a method, system, and
apparatus for perforating and/or fracturing multiple formation
intervals, which allows each single zone to be treated with an
individual treatment stage while minimizing the problems that are
associated with existing coiled tubing or jointed tubing
stimulation methods and hence providing significant economic and
technical benefit over existing methods.
[0176] Typically in wellbore completion, a packer type element,
such as a packer made of cement is used to isolate different
production zones from one another during the extraction process. In
many instances, such packing is done to better extract hydrocarbons
from a production zone where pressure, temperature pH and geologic
formation may make extraction from each area at once inefficient.
Inefficiency may result in the expenditure of excess chemicals,
lubricants, components and the like or may be in the form of
lowered hydrocarbon production or may be in the cost if increased
rig time.
[0177] Typically in a wellbore construction, once the original
wellbore is drilled, casing is added and cement pumped through the
interior of the casing out the bottom, where it flows back up
between the casing and the wellbore. The internal area of the
casing is then cleaned typically with a mechanical scrubbing
mechanism.
[0178] Once cleaning of the interior of the casing has been
accomplished the production zone of interest will be perforated.
One such method is using a mandrel with a fracture valve tool
running with a production string. The fracture valve tool may
comprise a mandrel defining a through passage smaller than that of
the production tubing.
[0179] An embodiment of the present invention is a system for
completing multi-zone fracture stimulated wells that provides for
cementing the casing in place except adjacent to a tubing mounted
rotary valve which has the capability of tolerating fracture
stimulation treatments through the valve. In various embodiments,
perforation can be eliminated and the treated zone can be protected
while other zones are treated. In various embodiments, the system
may be configured to allow all zones to be opened on a single
command or may be configured for selective zonal control once the
well is put on production.
[0180] In certain embodiments, the mandrel may be operatively
connected to a perforated casing. In such instances, the casing and
the mandrel comprising or consisting of a fracture valve tool may
have perforations. Likewise, the casing where it is contemplated to
place the mandrel with the fracture valve tool may also have
perforations, such that when the perforations from the casing and
the mandrel are not aligned, pumpable cement, upon exiting the
bottom of casing, is unable to reenter the interior of the casing
through the perforations.
[0181] In other embodiments, the mandrel may not be operatively
connected to a perforated casing, but rather adjacent to the area
with the perforated casing such that the space between the mandril
and the casing is minimal. In certain embodiments, it is
contemplated that the spacing prevents most or all of the pumpable
cement used during completion of the casing cementing process does
not reenter the interior of the casing.
[0182] In either embodiment, the perforations may not be aligned
with the perforations of the mandrel containing the fracture valve
tool during the cementing process. Once the wellbore operator is
ready to fracture a production zone, the mandrel containing the
fracture valve tool may be aligned with the perforated casing. This
alignment allows high pressure such as in the form of a controlled
explosion or gas or fluid injection to follow a path of least
resistance and penetrate the cement and enter the production
zone.
[0183] In embodiments wherein a mandrel comprising or consisting of
a fracture valve tool, either operatively connected to the
perforated casing or adjacent to the perforated casing is used in
fracturing the production zone to extract hydrocarbons, it is
contemplated that shrapnel or debris in the form of metal from the
casing will not enter the production zone. Thus the only debris
from the fracturing of the production zone will be in the form of
cement debris and geological debris from the production zone.
Accordingly, a lack of metal debris may result in either or both a
higher flow of hydrocarbons from the production zone and a
decreased cleanup time.
[0184] In addition to fracturing a production zone, a typical zone
will be isolated via the use of a cement, metal or composite plug
or packing device as discussed above. However, to extract
hydrocarbons from below the plug or packing device, it will often
be necessary to remove the plug or packing device through an
extraction means, drill through the plug or packing device
resulting in increased rig time and debris removal, or destroy the
plug or packing device such as through the use of a piston.
[0185] Methods of isolating zones previously included the use of a
plug. The plug may be comprised of cement, metal, or a composite
material. In such situations, it is necessary to drill through the
plug to reach the zones isolated below the plug. This requires
additional rig time. An advantage of embodiments of the present
invention is decreased rig time in comparison to when plugs need to
be drilled.
[0186] The fracturing process is a method of stimulating production
by opening channels in the formation. Fluid, under high hydraulic
pressure is pumped into the production tubing. The fluid is forced
out of the production tubing below or between two packers. Examples
of fracturing fluids are distillate, diesel, crude, kerosene,
water, or acid. Proppant material may be included in the fluid.
Examples of propping agents are sand and aluminum pellets. The
pressure causes the fluid to penetrate and open cracks in the
formation. When the pressure is released, the fluid goes back to
the well but the proppant material stays in the cracks.
[0187] Referring to FIG. 3, an embodiment of a fracture valve tool
100 comprising a mandrel 110, a mandrel port 127, an interior
surface of the mandrel 150, and exterior surface of the mandrel
140, a rotating sleeve 125, a sleeve port 120, spacer 131, a
control line 145, and cement flowpaths 105 and 109 is illustrated.
Further, a casing string section defines a longitudinally extending
borehole 107, through which cement also flows.
[0188] Referring to FIG. 4a, a cross sectional cut along A-A is
illustrated. Rotating sleeve 125 is illustrated in a closed
position whereby the interior of the casing string section cannot
communicate with the exterior of the casing string. Upon actuation
of the fracture valve, sleeve port 123 is capable of at least
partially aligning with mandrel port 127. Upon at least partial
alignment of the sleeve port 123 and mandrel port 127, the exterior
and interior of the casing string are in communication. Spacer 131
from FIG. 3 can be fractured out when production from the formation
is desired. The exterior of the casing string section 100 comprises
casing 130. In one embodiment, the fracture valve tool of the
present invention may be used in combination with the rotary valve
3 disclosed in the related application titled Processes and Systems
for Isolating Production Zones in a Wellbore, filed the same day as
the present application. In various embodiments, upon actuation of
the rotary valve 3, sleeve port 123 is capable of at least
partially aligning with mandrel port 127. Upon at least partial
alignment of the sleeve port 123 and mandrel port 127, the exterior
and interior of the casing string are in communication.
[0189] In typical embodiments, the at least one mandrel with rotary
valve 1 is in a closed position when being cemented in the zones of
interest. Optionally the cement has been weakened in the area of
the valve parts. In a zone of interest, the fracture valve tool is
opened wherein the sleeve port 123 is at least partially aligned
with mandrel port 127 and the formation is fractured. Advantages of
the present invention include, but are not limited to, that
formation is not damaged by metal during the fracture and rig time
is saved because it is not necessary to use plugs and drill the
plugs out when it is time for production. Damage to the formation
following fracture can decrease production as can the process of
removing the plugs.
[0190] Referring to FIG. 4b, a sectional cut along B-B in FIG. 3 is
illustrated. Cement flowpaths 132 are illustrated as not
interfering with the interior of the mandrel of any of the
ports.
[0191] Referring to FIG. 5, a casing string section 300 with a
rotatable sleeve in a longer casing section is illustrated. Port
310 for communication is visible. A connection of another casing
section is illustrated at connection 320.
[0192] Various embodiments comprise a fracture valve tool 100 for
running with a production string comprising at least one production
tubing, the fracture valve tool 100 comprising a mandrel 110
defining a through passage smaller than that of the production
tubing, a rotary valve 3 and a valve actuator 5. In various
embodiments, the valve actuator 5 can be actuated into at least a
first position wherein the rotary valve 3 is open and the through
passage is open and at least a second position wherein the rotary
valve 3 is closed and the through passage is closed. Various
further embodiments comprise at least one packer assembly
comprising at least one packer 415 and a mandrel 2. In various
embodiments, the at least one packer assembly is positioned above
the rotary valve 3. In various further embodiments, the at least
one packer assembly is positioned about a hydrocarbon producing
zone. Typically, the zone communicates with the packer assembly's
mandrel 2.
[0193] A fracture valve tool comprises a mandrel 110. The mandrel
110 has a first mandrel port 127 that extends from the exterior
surface 140 of the mandrel to the interior surface 150 of the
mandrel. There is a rotating sleeve 125 against the interior
surface of the mandrel. The rotating sleeve 125 is rotatably
positioned on said mandrel 110, and comprises at least one sleeve
port 123. The rotating sleeve 125, containing at least one sleeve
port 123, rotates between a first position where the sleeve port
123 covers the mandrel port 127 and a second position where the
sleeve port 123 is at least partially aligned with the mandrel port
127, allowing communication from the exterior of the mandrel 140 to
the interior surface of the mandrel 150. In one embodiment, the
rotating sleeve 125 is a ball valve or is on a ball valve.
[0194] A ball valve is a valve with a sphere with a hole through
the middle. When the hole is in line with the tube or pipe, flow
occurs. When it is turned a quarter turn, the hole is perpendicular
to the tube or pipe, flow is blocked.
[0195] The exterior of the mandrel port 127 is near the outside of
the casing formation and the interior is adjacent the rotating
sleeve 125. When the fracturing occurs, damage to the formation is
lessened because no metal from the casing string is blasted into
the formation.
[0196] In various embodiments, in a completed wellbore, the mandrel
with a rotary valve 1 is cemented in a closed position.
[0197] In one embodiment, there is at least one casing string
comprising a fracture valve tool comprising a rotating sleeve 125
positioned on a mandrel 110. The mandrel 110 comprises at least one
mandrel port 127 and the rotating sleeve 125 comprises at least one
sleeve port 123 per zone of production. The ports on the mandrel
110 and a sleeve may be aligned by rotating the sleeve in a
circumferential manner. In another embodiment, the ports on the
mandrel 110 and a sleeve may be aligned by sliding the sleeve in
vertical manner.
[0198] In various embodiments, the rotating sleeve 125 of the
fracture valve tool may be rotated via an actuator or other
suitable mechanism. The signal to rotate the rotating sleeve 125
may be delivered by the control line 145. In another embodiment,
the signal may be transmitted remotely. In one embodiment, the
fracture valve tool 100 may be acted upon by actuator 5. In other
embodiments, the fracture valve tool 100 may be actuated
electrically, pneumatically, hydraulically, thermally,
hydrostatically, or a combination thereof. The actuator may create
linear motion, rotary motion, or oscillatory motion. In certain
embodiments, the rotating sleeve and/or rotary valve may be
actuated based upon a signal transmitted from a downhole or surface
source. Power sources include batteries present in the casing
string section or lines containing hydraulic fluid or electricity.
Multiple actuation systems may be used in a given fracture valve
tool.
[0199] In one embodiment, the formation is optionally perforated
prior to fracturing. Perforation provides communication to the
reservoir. Once the fracture is initiated, the fracturing will
cause the area around the hole in the fracture valve to be blown
away. Perforating devices that may be used include, but are not
limited to, a select-fire perforating gun system (using
shaped-charge perforating charges) or a bar with fixed encapsulated
hollow charges oriented in a single direction. Fracture pressures
may be sufficient to cause the cement to fail in the area of the
perforation hole.
[0200] In various embodiments, such a valve arrangement as herein
disclosed would relieve stress to the formation, as no stressful
perforation would be required in various embodiments. As well,
cementing of the well would be impeded by cavities or rough
portions on typical completions. In various embodiments, the
mandrel interior surface is fairly smooth and would allow the
passage of a cement wiper plug.
[0201] Various further embodiments comprise a measurement line
extending from the mandrel for taking data measurements downhole at
about the production zone. Examples of measurements that might be
taken include but are not limited to density, temperature,
pressure, pH, and/or the like. Such measurements can be used to
help run the well. In various embodiments, a cable would
communicate the data to an operator at the surface. In various
further embodiments, the data is transmitted remotely to an
operator. In further embodiments, the data is stored.
[0202] Various deployment means for use in an embodiment of the
present invention were disclosed in U.S. Pat. No. 7,059,407 and
include coiled tubing, jointed tubing, electric line, wireline,
tractor system, etc. In one embodiment the assembly may be actuated
based upon a signal from the surface. Suitable signal means for
actuation from the surface, also disclosed in U.S. Pat. No.
7,059,407, include but are not limited to, electronic signals
transmitted via wireline; hydraulic signals transmitted via tubing,
annulus, umbilicals; tension or compression loads; radio
transmission; or fiber-optic transmission. An umbilical may be used
for perforating devices that require hydraulic pressure for
selective-firing. Umbilicals could also be used to operate a
hydraulic motor for actuation of components.
[0203] Various embodiments of the present invention comprise a
completed wellbore with at least a first production zone, the
completed wellbore further comprising a cemented casing string, a
production string, and at least one fracture valve tool 100 as
herein disclosed connected to the production string and positioned
below the first production zone. In further embodiments, the at
least one fracture valve tool 100 is cemented in a closed position
and/or open position. Further embodiments comprise a second
production zone and a second fracture valve tool 100 as herein
disclosed connected to the production string and positioned below
the second production zone, wherein the second fracture valve tool
100 is cemented in a closed and/or open position.
[0204] Further embodiments disclose a process for producing a
hydrocarbon from the completed wellbore the process comprising the
steps of: opening a rotary valve 3; fracturing a first production
zone; flowing a drilling mud through the completed wellbore for
clean up; and closing the rotary valve 3, wherein a hydrocarbon is
produced up the production string.
[0205] Further embodiments disclose repeating the steps of: opening
a second rotary valve 3; fracturing a second production zone;
flowing a drilling mud through the completed wellbore for clean up;
and, closing the second rotary valve 3, wherein a hydrocarbon is
produced up the production string.
[0206] Further embodiments disclose a process for producing a
hydrocarbon from the completed wellbore the process comprising the
steps of: opening a rotary valve 3 associated with a mandrel with a
rotary valve 1 comprising a mandrel 2 defining a through passage
smaller than that of the production tubing, a rotary valve 3 and a
valve actuator 5; and fracturing a first production zone.
[0207] In preferred embodiments, the fracture valve tool 100 may be
metal in design, the metal may be any metal or alloy known in the
art that is sufficient to prevent the flow of hydrocarbons through
the rotary valve when closed. In certain preferred embodiments, the
metal is steel, iron or titanium. In preferred embodiments the
metal is not reactive towards hydrocarbons. The rotary valve may be
for example from 1 mm in thickness to several centimeters in
thickness to account for any pressure from the hydrocarbon product.
In alternative embodiments, the rotary valve may be composed of a
plastic polymer, graphite, carbon nanotube, diamond, fiberglass,
glass, a ceramic, concrete, or other mineral compounds.
[0208] Such a valve arrangement as herein disclosed would relieve
stress to the formation, as no stressful perforation would be
required in various embodiments. As well, cementing of the well
would be impeded by cavities or rough portions on typical
completions. In various embodiments, the mandrel interior surface
is fairly smooth and would allow the passage of a cement wiper
plug.
[0209] Advantages of the design of the valve, include but are not
limited to: 1) The valve inner diameter is smooth and has no
recesses. This allows the cement wiper plug to pass through the
system and wipe the inner diameter clean. 2) A rotary valve rotates
along the inner diameter and in the scaling mechanism. 3) The
system incorporates open hole inflatable elements on both sides of
the valve. Cement is circulated through a path in the tool between
the inflatable elements which decreases outside of the valve. 4)
Three control lines may be used, one for actuating the external
casing packers, one line for opening valves, and one line for
closing valves. In another embodiment, a method is provided for the
selective operation of the individual valves for the purpose of
opening the rotary valve 3, flowing through drilling mud, closing
the rotary valve 3, and closing valves. In yet another embodiment,
more lines would be provided for individual line selectivity after
the completion phase. In another embodiment, an additional line in
excess of the number of zones may be used for complete selectivity
with one line being the common line connected to the open side of
the control piston. This does not necessarily need to be done from
the bottom up.
C. Rotary Valve
[0210] It is contemplated in certain embodiments of the invention
that a rotary valve may be used. In such embodiments, a rotary
valve may be operatively attached to the interior of a mandrel.
Accordingly, in the embodiments of the invention, it is
contemplated that a rotary valve mandrel, that is a rotary valve
operatively attached to a mandrel, may be used for plugging or
capping of a casing. The rotary valve mandrel may be above the
production zone. In certain embodiments, the rotary valve mandrel
may be used in addition to a mandrel with a fracture valve
tool.
[0211] Referring to FIG. 1, a sectional view of an embodiment of
the present invention comprising a mandrel with rotary valve 1, a
mandrel 2, a rotary valve 3, a valve tip 4, a piston 7, and a valve
actuator 5 is illustrated. A rotary valve 3 is in an open position.
A sectional view of an embodiment of the present invention
comprising a mandrel with rotary valve 1, a mandrel 2, a rotary
valve 3, a valve tip 4, a piston 7, and a valve actuator 5. The
blapper valve is a combination ball valve and flapper valve located
on top of a mandrel 2. However, any type of valve is capable of
use. In various embodiments, the mandrel 2 is also attached to an
actuator 5. In various embodiments, the rotary valve can be run
with a production string, cemented in and open automatically by
time or signal. In other embodiments, the rotary valve may not be
cemented in. Typically, a rotary valve would be positioned above
and below a formation with hydrocarbons. In other embodiments, the
rotary valve is positioned above a formation with hydrocarbons. In
various embodiments, the rotary valve can be run as casing for the
wellbore and production can occur after the valve is opened.
[0212] Referring to FIG. 2, the mandrel with rotary valve 1 of FIG.
1 in a closed position is illustrated.
[0213] When a mandrel with rotary valve 1 is used in addition to a
mandrel with a fracture valve tool 100, it is contemplated that the
mandrel with rotary valve 1 may be above the mandrel with the
fracture valve tool 100. In certain embodiments, the mandrel with a
rotary valve 1 sits atop the mandrel with the fracture valve tool
100. In other embodiments, the mandrel with rotary valve 1 is
attached to or is positioned atop casing allowing for a space
between the mandrel with a rotary valve 1 and the mandrel with the
fracture valve tool 100. In such embodiments, the length of casing
between each type of mandrel is about 1 cm to 100 m or more.
[0214] In certain embodiments, wherein the rotary valve 3 is within
a mandrel, the rotary valve 3 may also operatively connected to a
piston or wires or a shaft which may be operatively connected to an
actuator. In certain embodiments, the actuator may be operatively
connected internally to the rotary valve mandrel. In other
embodiments, the actuator may be operatively connected externally
to the mandrel with a rotary valve.
[0215] In embodiments of the invention wherein the rotary valve 3
is operatively connected to a piston or wires or a shaft, the
piston or wires or shaft may move the rotary valve from a closed
position wherein hydrocarbon flow is prevented to a partially open
position wherein hydrocarbon flow is partially restricted to a
fully open position wherein hydrocarbon flow is not restricted. In
certain application the rotary valve 3 may be 100% closed or 100%
open. In other applications, the rotary valve 3 may be 1%, 2%, 3%,
4%, 5%, 6%, 7%, 8%, 9% or 10% opened or closed or some percentage
in between. In other applications the rotary valve 3 may be from
11% to 99% open or closed or some percentage between.
[0216] In embodiments of the invention wherein the rotary valve 3
is operatively connected to a piston or wires or a shaft, the
piston or wires or shaft may be positioned above the rotary valve,
below the rotary valve or adjacent to the rotary valve. The
actuator for the piston or wires or shaft may also be positioned
above, adjacent to or below the rotary valve. In certain
embodiments, the actuator may be positioned above the rotary valve
wherein the piston or wires or shaft may be positioned below the
rotary valve. In such embodiments it may be necessary to reverse or
re-orient the force of the piston or wires or shaft on the rotary
valve through the use of a pulley or hinge, or joint type
mechanism.
[0217] In embodiments wherein the rotary valve 3 is closed, the
valve may be considered to have a cap or end above which no
hydrocarbon product may pass. In certain embodiments, the cap may
be flat, in other embodiments, the cap may be convex as viewed from
above the mandrel. In other embodiments the cap may be concave as
viewed from the top of the mandrel. In certain embodiments, wherein
the cap is flat, the closure may look diagonal as viewed from the
top of the mandrel. In such instances, the angle between the cap
and the internal portion of the mandrel may be an obtuse angle or
greater than 90.degree. and an acute angle of less than 90.degree..
In embodiments wherein the cap is flat, the closure may be
horizontal or perpendicular to the axis of the mandrel. In such
cases, the angle between the cap and the internal portion of the
mandrel may be 90.degree. as viewed from the top of the mandrel. In
certain embodiments, wherein the cap is concave or convex, the
closure may look diagonal as viewed from the top of the mandrel. In
such instances, the angle between the concave or convex cap and the
internal portion of the mandrel may be an obtuse angle or greater
than 90.degree. and an acute angle of less than 90.degree.. In
other embodiments wherein the cap is concave or convex, the closure
may be perpendicular to the axis of the mandrel.
[0218] In preferred embodiments, the rotary valve 3 may be metal in
design, the metal may be any metal or alloy known in the art that
is sufficient to prevent the flow of hydrocarbons through the
rotary valve when closed. In certain preferred embodiments, the
metal is steel, iron or titanium. In preferred embodiments the
metal is not reactive towards hydrocarbons. The rotary valve may be
for example from 1 mm in thickness to several centimeters in
thickness to account for any pressure from the hydrocarbon product.
In alternative embodiments, the rotary valve may be composed of a
plastic polymer, graphite, carbon nanotube, diamond, fiberglass,
glass, a ceramic, concrete, or other mineral compounds.
[0219] In one embodiment, a mandrel with rotary valve 1 (closed
position) is run in a casing string. The casing is cemented in the
well. Optionally the cement has been weakened in the area of the
valve parts. Cementing may be achieved by pumping cement down the
casing string. The cement is supplied under pressure and
consequently is squeezed up through the annular space between the
casing and the wellbore until it reaches the bottom of the well
casing when it passes up through the annular gap between the casing
and wellbore. The cement rises up between casing and the
wellbore.
[0220] Multiple valves are run in the casing with each being in a
zone of interest when the casing is cemented in place. In one
embodiment, in zone 1, the rotary valve 3 is opened, the first
production zone is fractured, drilling mud is flowed through the
completed wellbore for clean up; and the rotary valve 3 is closed,
wherein a hydrocarbon is produced up the production string. The
same is done for each zone of production. Production tubing and
packing is run and all valves are opened to comingle. The
individual valves can be used to control flow. An advantage of
embodiments of the present invention there is no impact on the
formation of the opening and closing the reservoir as opposed to
the standard method.
[0221] In one embodiment, a permanent gauge is run in each section
at the outer diameter of the valve to test the pressure on the zone
of interest after flowback.
[0222] There are many downhole applications where devices or
"tools" are required to be actuated. It is typical for example for
certain downhole tools to be run into position within the wellbore
or well casing in a retracted or a "run-in" configuration and to be
subsequently actuated such that they are in an engaged or "set"
configuration. Other tools may be placed in service initially to
perform a certain function and at a later time, or as a result of
changed circumstances, it is desirable that they be actuated in
order that they may perform an alternate function. For example, a
valve may be initially open such that it allows well production,
and later actuated to close and thus prevent wellbore production or
vise versa. The broad variety of downhole tool applications has
driven an equally diverse number of tool designs. However, many of
these mechanical tools share the quality of having at least two
mechanical states, a first before actuation and a second state
subsequent to actuation. Actuation of these tools requires that
mechanical work be done; that is a force needs to be applied over a
displacement to move the tool from its first state to its second
state. Such dual state tools are often characterized with certain
components arranged and constrained such that the tool can be
actuated so long as a force and its reaction can be made to be
applied at specific component attachment points to cause a linear
motion. The present invention is an actuator which is adaptable to
many such dual state tools. The actuator's use is not constrained
to any particular type of tool since it may be applied to any
downhole tool that can be adapted to a linear actuator with the
qualities described.
[0223] Methods of actuating downhole tools which have been placed
wells include performing a through tubing intervention such as with
a wire line where shifting tools are run into the well on wire line
such that the shifting tool engages a profile within the tool.
Subsequent and manipulation of the wire or use of a wire line
setting tool can impart mechanical forces onto movable members of
the downhole tool. However, it may not be possible or convenient to
access the tool with a wire line as high well deviations can
frustrate wire line operations. This limitation may be overcome
with a less economical approach of using coiled tubing or a
motorized tractor device. Regardless of whether coiled tubing, a
motorized tractor device or a wire line, wellbore obstructions can
frustrate these intervention operations.
[0224] Many tools are designed to be operated hydraulically and
such tools normally contain piston arrangements and are operated
when a differential pressure is imposed on the piston. Such tools
are typically configured whereby a differential pressure from the
wellbore tubing to a wellbore annulus is applied. The pistons in
such tools are normally pinned or otherwise latched so that the
tool is held in its first state until a prescribed threshold value
of pressure differential is exceeded and once the threshold is
exceeded the tool normally will partially actuate immediately but
in most cases a still greater pressure is required to fully actuate
the tool, for example a packer that may need very high pressures to
be applied to fully pack off the sealing elements. For applications
where it is desired to selectively activate multiple tools that are
run in a well in tandem different threshold values may be used for
each tool but this approach practically limits the number of tools
that can be run in tandem. Furthermore a means of temporarily
isolating the tubing from the annulus must often be employed. If
the plugging means is to be installed or removed through the tubing
obstruction limitations and conveyance limitations previously
described can result. Differential pressure operated tools normally
require that the additional pressure to cause the differential
pressure is supplied by pumps at the surface which may not be
readily available with sufficient capacity for such operations.
[0225] Downhole tools have been used that rely on atmospheric
chambers to be used on one side of the piston such tools are often
referred to as hydrostatically set. Hydrostatic set tools are
normally designed such that the static pressure from the wellbore
tubing or the wellbore annulus is sufficient to completely actuate
the tool. In order to place these tools without prematurely
actuating them the piston is normally locked down with a mechanical
locking device made from solid materials such as alloy steel. The
mechanisms are usually provided so that the required force applied
to unlock the mechanism is relatively low compared to the force
that the locking mechanism is retaining. This is a result of the
fact that the piston within the tool is invariably subjected to the
full differential between wellbore hydrostatic pressure and the
atmospheric pressure on the opposite side of the piston. Since the
piston seal must operate dynamically during the actuation phase
where it required to stroke, such a seal has to be of a design
compatible with dynamic movement and such seals will normally
include resilient or elastomeric components. Such dynamic seals are
often less reliable than seals designed for static applications or
in particular static seals that involve metal contact only. While
such dynamic seal designs may be adequate for typical operations,
very small leak rates across such piston seals that may go
undetected can cause the atmospheric chamber to be compromised and
the tool to fail to fully actuate when required. Various means have
been employed to release the piston locking mechanisms used in
hydrostatic set tools. Typically this involves establishing a
differential pressure from tubing to annulus and such an approach
can suffer many of the same limitations as described for
differential pressure operated tools.
[0226] Another configuration used for hydrostatic set tools is for
the operating piston to be pressure balanced with atmospheric
pressure on both sides of the piston. When actuation is desired, a
wellbore fluid is made to enter one side of the operating piston to
establish the differential pressure for tool operation. Such tools
normally also suffer from the same problems of dynamic seals
referenced previously, but in this case such seals typically define
a barrier between the wellbore and one of the atmospheric chambers.
Such systems may also suffer from the prospect of seal failure or
slow leakage into the intended high pressure side of the piston
which can cause premature tool actuation. This characteristic is
not affected by the method intended for allowing the wellbore
hydrostatic to be applied to the piston.
[0227] Various embodiments of the invention include a small
diameter linear actuator device for use with a downhole tool that
provides a system including a communications interface used for set
up on surface or alternatively for connection to a downhole
communication network. In an embodiment of the present invention,
the system includes a programmable controller and actuation
mechanism that produces an axial motion with relatively high force
that can be used for reliably activate downhole mechanical tools.
The system may use well bore hydrostatic pressure as the basis of
the force generation or any other suitable basis for the force
generation. In various embodiments of the invention, the system is
modular and adaptable to various wellbore tool applications. In
various embodiments of the invention, the actuator can be attached
to a well tool to provide a stroking force to move or function an
attached tool one time in one direction.
[0228] Various methods of actuating the valve actuator are
possible. In an embodiment a battery pack is operably connected to
the valve actuator. The battery pack can be used to supply power to
all manner of actuation devices and motors, such as a pneumatic
motor, a reciprocating motor, a piston motor, and/or the like.
Alternatively, power may be supplied through the control line. In
various further embodiments, the actuator is controlled by a
control line from the surface. The control line can supply power to
the actuator, supply a hydraulic fluid, supply light, fiber optics,
and/or the like. In an embodiment, there are three control lines
running to the actuator, such that one opens the actuator, one
closes the actuator, and one breaks any cement that is capable of
fouling the actuator and preventing it from opening. The cement on
the actuator may be broken by any method common in the art such as
vibration, an explosive charge, a hydraulic force, a movement up or
down of the valve, and/or the like. Generally, any necessary
structures for performing the vibrations, charges, movements,
and/or the like can be housed in the mandrel about the valve.
[0229] In various embodiments, a piston is operably connected to
the valve actuator 210 for rotating the rotary valve 3 between the
open position and the closed position. In various further
embodiments, a valve actuator at least partially opens the valve.
Further embodiments comprise a valve actuator that is capable of
selectively actuating the rotary valve to a desired position.
[0230] In various embodiments, components of an actuator system may
include a measurement conduit and a check valve. The measurement
conduit can be used for conveying any necessary instrumentation
downhole, including, but not limited to a fluid, i-wire, a fiber
optic cable, and/or any other instrumentation cable or control line
for taking measurements, providing power, or device or tool
necessary for operation of the system or operable with the system.
Measurement devices conveyed down the measurement conduit can
measure parameters including, but not limited to temperatures,
pressures, fluid density, fluid depth and/or other conditions of
fluids or areas proximate to or in various portions of the
formation or wellbore. Additionally, fluids, chemicals, and/or
other substances may be injected or conveyed downhole through the
measurement conduit.
[0231] In various embodiments, a systems can include an actuator
for opening, closing, rotating or otherwise controlling the
orientation of the valves. The actuator can include one or more
hydraulic actuators, electric actuators, mechanical actuators,
combinations thereof or any other actuator capable of controlling
the orientation of valves of a system. One or more umbilical can be
run downhole from the surface to provide signals to the actuator to
control the orientation of valves of a system.
[0232] In one embodiment the actuator is a hydraulic actuator for
controlling the orientation of valves of a system. A system can
further include one or more hydraulic umbilical through which a
hydraulic power signal or force can be transmitted to the actuator
from the earth surface. The actuator controls the orientation of
valves of a system in response to the hydraulic power signal or
force.
[0233] The hydraulic actuator can be configured to control the
orientation of valves in response to a differential pressure
between a pressure of a first hydraulic umbilical and a pressure at
a point within the subterranean well. The hydraulic actuator can be
configured to control the orientation of valves in response to a
differential pressure between a pressure within a first hydraulic
umbilical and a pressure within an injection conduit. The hydraulic
actuator can be configured to control the orientation of valves in
response to a differential pressure between a pressure within a
first hydraulic umbilical and a pressure within the return conduit.
The hydraulic actuator can be configured to control the orientation
of valves in response to a differential pressure between a pressure
within a first hydraulic umbilical and a pressure within a second
hydraulic umbilical.
[0234] In various embodiments, a system can further include a gas
holding chamber pre-charged with the injection gas for injecting
gas through the injection conduit and into a container. The
hydraulic actuator can be configured to control the orientation of
valves in response to a differential pressure between a pressure
within a first hydraulic umbilical and a pressure of the gas
holding chamber.
[0235] In another embodiment, the hydraulic power signal can be
sent through the gas injection conduit from the earth surface. The
hydraulic actuator can be configured to control the orientation of
valves in response to a differential pressure between a pressure
within the gas injection conduit and a pressure at a point within
the subterranean well. The hydraulic actuator can be configured to
control the orientation of valves in response to a differential
pressure between a pressure within the gas injection conduit and a
pressure within the container. The hydraulic actuator can be
configured to control the orientation of valves in response to a
differential pressure between a pressure within the gas injection
conduit and a pressure within the return conduit. The hydraulic
actuator can be configured to control the orientation of valves in
response to a differential pressure between a pressure within the
gas injection conduit and a pressure within a hydraulic umbilical.
The hydraulic actuator can be configured to control the orientation
of valves in response to a differential pressure between a pressure
within the gas injection conduit and a pressure within a gas
holding chamber.
[0236] In yet another embodiment, the actuator is an electric
actuator for controlling the orientation of valves of a system. The
electric actuator can be a solenoid, an electric motor, or an
electric pump driving a piston actuator in a closed-loop hydraulic
circuit. A system can further include one or more electrically
conductive umbilical through which an electric power signal can be
transmitted to the actuator from the earth surface. The actuator
controls the orientation of valves of a system in response to the
electric power signal.
[0237] In one embodiment, an actuator for controlling the
orientation of valves of a system includes a communications
receiver for receiving a communication signal, a local electrical
power source for powering the actuator, a controller responsive to
the communication signal, and a sensor interfaced with the
controller for providing an indication of the presence of at least
one subterranean fluid to be removed from a the subterranean
well.
[0238] In one embodiment, the receiver is an acoustic receiver and
the communication signal is an acoustic signal generated at an
earth surface, a wellhead of the subterranean well or other remote
location. In another embodiment, the receiver is an electromagnetic
receiver and the communication signal is an electromagnetic signal
generated at earth surface, a wellhead of the subterranean well or
other remote location.
[0239] The local electrical power source for powering the actuator
is can be a rechargeable battery, a capacitor, or an electrically
conductive cable energized by a power supply located at earth
surface, a wellhead of the subterranean well or other remote
location.
[0240] In various embodiments, the controller of the actuators of
the present disclosure can include a programmable microprocessor.
The microprocessor can be programmed to operate the actuator and
control the orientation of valves in response to the communication
signal received by the receiver.
[0241] In an embodiment of the present invention, the actuator may
contain a sensor. The sensor may be used to sense heat, pressure,
light, or other parameters of the subterranean well or wellbore. In
one embodiment the sensor includes a plurality of differential
pressure transducers positioned in the subterranean well at a
plurality of subterranean depths.
[0242] Referring to FIG. 7, two well completions are illustrated.
Well completion 400 is an illustration of multiple valve tools 410,
multiple production zones 420, ports 419, packers 415, cemented
section 430, and bottom sub or packer 417. Well completion 500 is
an illustration of a casing string section 510, production zones
520, cemented section 530, rotary sleeve 515, and packed section
517.
[0243] In an embodiment, with reference to FIG. 7, two different
systems are disclosed for solving a common problem.
[0244] Wellbore 400 illustrates a system whereby a wellbore 430 was
drilled and fractured. Multiple valve tools 410 are run in the
casing abutting a production zone in a closed position. On signal
or at a predetermined time, each valve on at least one of valve
tool 410 is opened to allow production. Various arrangements of the
valve tools are capable of use with varying embodiments of the
present invention, such as a valve tool positioned both uphole and
downhole from a formation for the production of oil and gas.
[0245] Wellbore 500 illustrates a system whereby a wellbore 530 was
drilled. A rotary valve tool, comprising a rotary valve sleeve, is
then run into the wellbore along with casing. In various
embodiments, the rotary valve tool is aligned with a zone for
production. In various embodiments, after running of the casing and
the rotary valve tool, cement is flowed into the annular space, but
not in the area from which production is desired. To begin
production, the rotary valve is actuated and the rotary valve tool
exposes a communication pathway from the interior of the wellbore
to the formation. Fracturing of the formation can then occur
through the communication pathway.
[0246] A well completion system comprising of a at least one casing
mounted rotary valve wherein the casing is cemented in place except
for the annular space exterior to the rotary valve
[0247] The system of claim 1 wherein the at least one rotary valve
is controlled from the surface through an at least one hydraulic
line cemented in place.
[0248] The method of completing a well with the completion system
of claim 2 comprising the steps of:
[0249] running the at least one casing mounted rotary valve to
depth in the closed position, such rotary valve incorporating an
annular fluid bypass means. between two casing mounted packers;
[0250] actuating the packers,
[0251] cementing the casing in place and forcing the cement to pass
through the annular bypass means and thus not creating a seal
against the formation in the section outside the rotary valve and
between the two packers; and opening the rotary valve to establish
wellbore communication with the reservoir
[0252] The method of claim wherein at least two rotary valves are
included in the casing string and further comprising the steps
of;
injecting stimulation fluid from wellbore into the formation
through the first valve; producing fluid from the formation through
the first valve; closing the first valve; opening the second; and
injecting stimulation fluid from wellbore into the formation
through the second valve
[0253] Preferably, the actuator as designed is for single shot
operation. The actuator may be attached to a well tool to provide a
stroking force to move or function an attached tool one time in one
direction.
[0254] Preferably, an actuator module is used with a downhole tool.
The actuator module may provide a method for selectively operating
the downhole tool by delivering a force through a displacement. In
certain embodiments, the actuator module may be attached to the
downhole tool. In other embodiments, it may be incorporated into a
downhole tool. Preferably, the force delivered is derived from the
full hydrostatic wellbore pressure acting across a piston.
Preferably, prior to activation the piston is supported by a fixed
volume of fluid at hydrostatic pressure. Upon actuation, the fluid
may be allowed to be evacuated into a separate atmospheric
chamber.
[0255] FIG. 8A and FIG. 8B show a preferred embodiment of the
device in its pre activated state. The device is to be connected to
a downhole tool at two points. One point of connection must be
linked to the actuator piston 604; the linkage member 603 provides
this functionality. The other point of connection is shown to be at
the threaded end 620 of the housing 601. One operating member of
the downhole tool is shown as 5A, and is configured in this
instance as a threaded cylinder. The second operating member of the
downhole tool is shown as item 5B, and in this instance is
configured as a pin.
[0256] A flow path means including hole 607A and annular space 607B
is provided for allowing the wellbore fluid 608 to communicate with
the one side piston 604B and linkage member 603.
[0257] A fixed volume of incompressible fluid 606 is contained in a
cylindrical chamber 602. The chamber 602 is defined by the housing
601, side 604A of piston 604, a disk 611, and a disk support member
610. O-ring 700 installed between the disk support member 610 and
engaging the housing 1 as well as second o-ring 701 installed in
piston 604 and engaging the piston isolate the fluids 606 in the
cylindrical chamber 602 from fluids in the wellbore 608. However,
it may be seen that since piston 604 is exposed to well bore fluids
608 on piston side 604B that the pressure in the chamber 602 will
also be at hydrostatic pressure and therefore in this pre-actuated
state, o-ring 700 and 701 are not subject to differential pressure.
A second atmospheric chamber 612 is isolated from the first
cylindrical chamber 602 by disk 611 and disk support member 610
which are both constructed of alloy steel in the preferred
embodiments.
[0258] A separate section of the tool contains a printed circuit
board 621 or PCBA mounted to chassis 618. The PCBA 621 includes
many electrical components which in the preferred embodiment the
PCBA 621 include a micro-processor/microcontroller based controller
613 and onboard vibration and temperature sensors as well as
various connection means. Also shown is a power source 617 in this
instance configured as a battery. Wire set 800 provide a connection
between the controller 613 and an opening module 614 which provides
a means of controller generated output signal to be delivered to
the opening module. Second wire set 801 provides the means of
powering the PCBA components and controller 613 from the power
source 617. Bulkhead 622 provides a pressure barrier between the
section of the tool containing the controller 613 and the second
atmospheric chamber 612. This bulkhead 622 allows for the
controller to remain active after activating the opening module and
actuating the device especially when the incompressible fluid 602
is a conductive fluid. The separation that bulkhead 622 provides
can be omitted where it is not necessary that the controller 613
continue to operate after actuation.
[0259] Opening module 614 is shown mounted within the isolation
module 609. In this instance the opening module 614 shown is
pyrotechnically activated it includes a contained amount of
pyrotechnic material 616. Shown in its pre activated state the
cutting dart 615 is not in contact with disk 611.
[0260] End cap 619 is shown which provides pressure isolation
between the wellbore 608 and the interior of the tool containing
the power source 617 and PCBA 621.
[0261] In this pre-actuated condition the piston 604 and linkage
member 603 are limited from moving into the housing 601 by the
reactive force provided by the incompressible fluid 602. Also shown
is shoulder 623 of housing 601 which limits movement of the piston
604 and linkage member 603 from being retracted from the housing
601.
[0262] FIGS. 9A and 9B show a preferred embodiment of the device in
its activated state. Just prior to this state, conditions set
within a program running on the controller 613 were satisfied such
that the controller 613 generated an electrical output signal to
activate the opening module 614. In this instance electric output
of the controller provided sufficient current through the wire set
800 to the pyrotechnic material 616 in the opening module 614 to
cause the material 616 to ignite and generate pressure driving the
cutting dart 615 with force to puncture disk 611. The cutting dart
615 is designed to include a linear grove 810 such that in the
event that it does not retract from the perforated hole, a fluid
communication path 810 between the cylindrical chamber 602 the
second atmospheric chamber 612 is provided for the compressible
fluid 606 to pass. In this condition the piston 604 and linkage
member 603 have been retracted into the housing 601 by the well
hydrostatic forces acting against the piston 604. The associated
relative movement of the downhole tool operating members 605A and
605B cause the downhole tool to operate.
[0263] FIG. 10A Shows an Isolation module 10 with integral thin
target section 820.
[0264] FIG. 10B Shows Isolation module 610 with a disk 611 welded
830 to a face of a support member 609. The weld 830 is preferably
done with an electron beam process. This arrangement is often
preferable to that shown in FIG. 11A because more precise
mechanical properties are obtainable from the use of a disk 611
than an integral thin section 820 in FIG. 3A.
[0265] FIG. 10C Shows Isolation module 610 with a disk 611 welded
830 to a face of a support member 609. The weld 830 is preferably
done with an electron beam process. A diverging radii 840 is shown
at the interface between the hole 850 provided in the support
member 609 and disk 611. The disk 611 is shown to be partially
pre-formed against the radii 240. Pre-forming as such in assembly
and the additional support that the radii 840 gives the disk 611
has been shown to improve the reliability of the disk 611 to
sustain certain high differential pressures.
[0266] FIG. 11A Pyrotechnic driven opening module 614 prior to
actuation shown with cutting dart 615 retracted and pyrotechnic
charge 616 prior to activation.
[0267] FIG. 11B Pyrotechnic driven opening module 614 after
actuation shown with cutting dart 615 extended and perforating
through disk 611 and providing flow path 610 and pyrotechnic charge
616 expanded and under pressure after activation.
[0268] FIG. 12A Shows a spring 900 driven bimetallic fuse wire 902
activated opening module 901 installed into an isolation module 609
before device actuation. Cutting dart 615A is held off disk 611 by
a bimetallic wire retainer 902. Such a wire 902 is exemplified by a
material manufactured by the Sigmund Cohn Corp of Mount Vernon,
N.Y. known by the trademark of PYROFUZE.RTM.. Wire retainer 902 is
shown placed within helical grooves on cutting dart 615A and a
solid ring 903. Spring 900 is in a compressed state. Heating
element 910 is shown to be in intimate thermal contact with the
wire retainer 902 within a volume of insulated potting material
911.
[0269] FIG. 12B Shows a spring 900 driven bimetallic fuse wire
(shown in FIG. 12A as item 902) activated opening module 901
installed into an isolation module 609 after device actuation. In
this view deflagration of wire retainer 902 has occurred (and so it
is no longer visible) in response to the heat generated by the
current of the controller's electrical output signal delivered
through wire set 800 to heating element 910 which was originally
contacting the wire retainer. With the wire no longer present in
solid form, dart 615A no longer constrained and is released to
respond to the spring force with motion, spring 900 is shown to
have forced the dart to move and to perforate disk 611.
[0270] FIG. 13A Shows a spring 900 driven solenoid activated
opening module 901 installed into an isolation module 609 prior to
device actuation. Cutting dart 615A is held off disk 611 by a
threaded and split retainer 903 and the solenoid sleeve 904. Spring
900 is in a compressed state.
[0271] FIG. 13B Shows a spring 900 driven solenoid activated
opening module 901 installed into an isolation module 609 after
device actuation. In this view the retainer support member 904 has
been driven linearly off of the split retainer 903 in response to a
magnetic force produced from the current in conductor set 800
provided by a controller. Split retainer 903 no longer constrained
by the solenoid sleeve 904 is permitted to disengage radially out
ward from threaded engagement of the cutting dart 615A. With dart
615A no longer constrained, spring 900 is shown to have forced the
dart to move and to perforate disk 611.
[0272] FIG. 14 Shows an interface to electrically conductive
instrument wire or (I-wire) cable assembly. I-wire cable assemblies
1006 are commonly used for transmitting communication and low power
signals between surface and downhole devices. These are cable
assemblies constructed within a stainless steel metal tube 1000
which are normally 0.250 inches or 0.125 inches in outer diameter.
An insulation layer 1001 is used to isolate the conductor cable
1002. A set of metal ferrule seals 1004 are energized by a jam nut
1003 to seal between the tube 1000 and tool end cap 1010 which
isolates the wellbore fluid 1007 from the interior of the tool
1008. The conductive cable is conductively attached to a feed
through within a bulkhead insulator 1009. A cable assembly wire
1005 is also conductively connected to the feed through within the
bulkhead insulator 1009 and connected as required to connections
points within the I-Wire cable assembly PCBA 1011. Depending on the
application wire 1005 can service a transceiver or a power supply
among other functional components. An electrical power and
communication circuit can be established with a common ground
including the I-Wire cable assembly device body 1012 and the
stainless tubing body 1000.
[0273] FIG. 15A Shows a solenoid valve based opening module 1102 in
the pre-actuated state. Opening module 1102 contains a normally
extended valve stem 1101, which in this view is sealed on and
engaged by an internal spring against a valve seat 1100 in the
isolation module 1106.
[0274] FIG. 15B Shows a solenoid valve based opening module 1102
after actuation. Upon activation of the solenoid valve 1102, by the
electrical signal provided through wire set 800, the valve stem
1101 retracts from the valve seat 1100 providing a fluid
communication path 1107 across the isolation module 1106.
[0275] From the foregoing description, one skilled in the art can
easily ascertain the essential characteristics of this disclosure,
and without departing from the spirit and scope thereof, can make
various changes and modifications to adapt the disclosure to
various usages and conditions. The embodiments described
hereinabove are meant to be illustrative only and should not be
taken as limiting of the scope of the disclosure, which is defined
in the following claims.
* * * * *